In most European grids, getting a new project connected is a long wait. Developers queue for years to receive “firm” access - the right to inject or draw their full contracted power at any time. A few European regulators have now started offering a different deal: connect fast, but accept that in a small number of hours each year you will be asked to curtail. That is a non-firm grid connection, and for batteries it is emerging as one of the single biggest levers for accelerating deployment this decade.
The trade
The core bargain is simple. A firm connection costs more and takes longer because the grid operator has to reinforce the local network to accommodate worst-case conditions. A non-firm connection costs less and comes faster because the project contractually accepts curtailment in the worst-case windows. For a battery, which is physically designed to absorb and release energy flexibly, the cost of occasional curtailment is materially lower than for a wind or solar plant whose revenue loss tracks generation one-for-one.
What the Netherlands study actually modelled
A 2025–2026 peer-reviewed Energy Policy paper [1] co-optimised firm and non-firm connection choices for BESS in the Netherlands. The headline result: a project accepting up to 15% curtailment in exchange for a 65% reduction in grid connection fees clears a higher net present value than the firm-connection counterfactual in nearly every modelled scenario. The loss from curtailment is smaller than the capex and grid-fee savings. Critically, the model accounted for the interaction between curtailment and market arbitrage: in the hours when the grid asks for curtailment (typically midday solar surplus or evening load peaks in the same local zone), wholesale spreads are often already high, and the battery compensates in the neighbouring hours.
How other European markets are moving
Germany has been the furthest along with its §14a EnWG regime, which allows flexible network tariffs for controllable loads including batteries and EV chargers. The Netherlands regulator ACM formalised non-firm connections (“flexibele aansluiting”) as a regulated product in 2024 and 2025. Belgium’s Elia and France’s Enedis both operate variants: Elia has piloted interruptible connections for industrial loads; Enedis offers “raccordement à puissance dynamique” in constrained zones. The UK’s National Grid ESO has run the Technical Limits process for years, and the ongoing reform to transmission connections (the REMA and TMO4+ processes) is explicitly expanding the space. Italy, Spain and Poland are all consulting on equivalent mechanisms in 2025–2026.
What it means for a developer
Three operational consequences follow. First, a non-firm project needs a more sophisticated optimiser. Curtailment windows are not random: they follow local congestion patterns, which are usually predictable and sometimes correlated with the same high-spread market hours. An optimiser that can pre-position state of charge ahead of likely curtailment windows recovers most of the foregone energy in neighbouring hours. Second, financing terms change. Lenders have been cautious on non-firm projects historically; the emerging precedent - including Dutch banks now underwriting non-firm BESS in 2025 - is that curtailment history over the previous 12–24 months from the local TSO is sufficient for debt sizing. Third, siting becomes more intentional: rather than filtering for the cleanest grid nodes, developers can target constrained nodes where the non-firm discount is largest and the battery is physically useful to the TSO.
The systemic logic
Non-firm connections work because they move the marginal cost of access from the system (grid reinforcement) to the project (occasional curtailment) and let batteries shoulder a cost they are physically well-placed to shoulder. Where firm connection requires 3–5 years and multi-million-euro substation works, non-firm connection can be completed in 12–24 months with minor local reinforcement. For a policy maker, it is one of the cheapest available mechanisms to accelerate deployment without raising the system cost for every other network user.
If Europe is going to triple or quadruple its battery fleet by 2030, a meaningful share of that capacity will come in through non-firm connections. The regulatory design question through 2026–2027 is how tightly to standardise the product: a patchwork of national rules will work, but a common European framework (an extension of the Network Code on Grid Connection, for example) would reduce risk premiums and accelerate the curve further.